Denbury Inc.

Okay. Thank you, Zack, and good morning, everyone.

And thank you for joining on today's call. Presenting today from Denbury will be Phil Rykhoek, our President and Chief Executive Officer; Mark Allen, our Senior Vice President and Chief Financial Officer; and Craig McPherson, our Senior Vice President and Chief Operating Officer.

Before we begin the call, let me remind you that today's call will include forward-looking statements that are based on the best and most reasonable information we have today. There are numerous factors that could cause actual results to differ materially from what we discuss on today's call.

And you can read our full disclosure on forward-looking statements and the risk factors associated with our business in our corporate presentation, our latest 10-K, and today's news release, all of which are available to you on our website denbury.com. Also, during the course of today's call, we will reference certain non-GAAP financial measures.

Reconciliations of and disclosure on these measures are provided in today's news release. With that, I'll turn the call over to Phil.

Thank you, Jack. Let me begin by talking just briefly about the current macro-environment.

As everyone knows, that oil prices dropped considerably over the last couple of months. And WTI future prices are now below $80, both short and long term.

Of course, finally, the equity evaluations of oil companies have dropped significantly, including ours. I wish I knew what the oil prices will be going forward, but to be candid, I do not.

There are some that suggest prices could drop more, and others presume prices have hit the bottom. In any case, though, let me highlight why I think Denbury is well situated to weather this price dip.

Denbury's assets and strategy put it in a uniquely positive situation under these circumstances. As we have historically stated, we believe we could cut spending by almost 50% and hold production roughly flat.

In other words, we can reduce our capital development program significantly, without shrinking the company. Some think that once you start an EOR flood you can stop or slow down development, that simply isn't true.

As we can adjust the development pace to almost any rate. We don't have any lease expiration issues like most of our peers, our assets will not go away if development is slowed, and really, the only negative impact is the decrease in the present value of the cash flow streams.

In addition to the advantages inherent in the assets, we've been hedging a portion of our forecasted production 12 to 24 months into the future, fairly consistently for the last several years. As such, we have about 75% of our current oil production hedged through the third quarter of 2015, with the -- a bit less hedge from the fourth quarter of '15 through the first half of the '16.

About half of the 2015 hedges are swaps with prices in the low $90s, and the balance collars with a floor price of around $80. Lastly, our capital structure is such that most of our debt is termed out with attractive interest rates, lowering the risk that lower oil prices could impact the liquidity we currently have under our bank line.

In summary, we feel that we feel very good about our ability to withstand lower oil price, and believe we're in a better position to do so within much of the industry. Nonetheless, we are reviewing our 2015 spending plans in light of the current environment.

The current oil price is about $12 to $13 a barrel, below our stated 2015 budget price of $90. So that decrease does, obviously, have an impact on our projected available cash.

As you know, we attempt to fund our capital spending and dividends with cash flow from operations. So we are currently evaluating options for 2015, in light of the anticipated reduced revenue due to commodity prices.

With our Analyst Day just a couple of weeks away, we won't be addressing our 2015 plans on today's call, but suffice it to say, we are acutely aware of the current environment and are evaluating our options. We look forward to providing you a comprehensive overview of our operations and 2015 estimates in our Analyst Day presentation in about 10 days.

As you know, we've worked hard to reduce our cost in 2014 and that program is continuing. I'm pleased we have generated about $90 million of free cash thus far this year, over and above free cash defined as cash flow from operations over and above capital expenditures and dividends.

And at least part of that free cash is due to our emphasis on cost control. As we announced during the last earnings call, we were running below budget on our capital spending, but noted we may rearrange some of our capital budget programs to end the year closer to $1.1 billion budget.

We anticipate we may spend at a somewhat faster pace in the fourth quarter than what we did in the first 3, but we still expect to end the year a bit below budget, with regard to capital spending. Therefore, even with the lower oil prices, we should end the year with excess free cash flow.

If you analyze our LOE cost per barrel, they are down about 20% since the fourth quarter of 2013. And that's $22.86 per barrel this quarter versus $28.67 in Q4 of 2013.

Unfortunately, if you dig a little deeper, it's not quite as good as that initially looks. If you adjust for the non-recurring items related to the Delhi incident, both including the insurance received and the incremental charges and adjust for incremental work-over cost at Riley Ridge.

The net decrease per barrel is reduced [Audio Gap] interestingly enough though, this year, why our EOR is running a little bit behind, primarily, due to delays in CO2 injection in Bell Creek discussed earlier this year. The bigger issues have been with conditional production from the aforementioned items.

These shortfalls are not acceptable and we are working to address them. So with that introduction, let's Mark and Craig give you more details.

Mark?

Thanks, Phil. My comments will summarize some of the notable financial items in our release, and primarily focusing on the sequential changes from the second quarter.

I will also provide some forward-looking statements guidance to help you in updating your financial models to reflect the current outlook for the fourth quarter of 2014. Our non-GAAP adjusted net income for the third quarter was $91 million or $0.26 per diluted share that was down $2 million from the second quarter, due primarily to lower realized commodity prices and production, offset by lower costs.

Our GAAP net income was significantly higher than this, due mostly to a gain of $277 million on fair value adjustments related to our hedge positions, and a $10 million gain related to the net impact of Delhi insurance recoveries, offset by incremental costs. Turning to cash flow, our non-GAAP adjusted cash flow from operations, which excludes working capital changes, was $316 million for Q3, up $2 million from the second quarter.

Lower prices on production decreased our cash inflows by roughly $10 million this quarter, however, we saw roughly the same increase from our Delhi insurance recovery, net of incremental costs, and also received an approximately $8 million benefit from severance tax exemption at Hastings Field. Other changes in cost and current taxes net down the remaining difference.

Our realized oil prices this quarter, excluding hedges decreased a little over $5 per barrel from Q2 to $94.78 per barrel, as oil prices trended down during the quarter. Including hedges, our net realized oil price was down only $1.40 per barrel from Q2.

Our NYMEX differential improved $0.50 from Q2 to approximately $2.50 per barrel below NYMEX during Q3. Oil differentials for our Gulf Coast tertiary properties, which primarily receive LLS pricing, averaged $2.37 per barrel above NYMEX, up approximately $1.20 per barrel from Q2.

In the Rocky Mountain region, our Cedar Creek Anticline oil differential declined by approximately $1.40 per barrel, selling at just under $11.70 per barrel below NYMEX this quarter. We currently expect our overall differential to average between $2 and $4 per barrel below NYMEX prices in the fourth quarter.

Moving to our hedging positions. Our oil hedges for the fourth quarter of 2014 are all fixed price NYMEX-based swaps with the weighted average settlement price of roughly $92.50.

These hedges covered approximately 80% of anticipated oil production in Q4. During the third quarter, we added to our 2015 and 2016 hedge positions, adding a combination of both NYMEX and LLS fixed price, enhanced swaps and 3-way collars.

For 2015, we have roughly 75% of our oil volume -- oil volumes hedged based on current production levels with an average downside price of approximately $87 per barrel based on our combined WTI and LLS hedges. Full details of our hedging positions are shown in the investor presentation that is available on our website.

On the expense side, LOE per BOE was in line with our previous guidance and we estimate LOE per BOE will remain in the mid-20s in Q4. Craig will discuss more about LOE in detail in his comments.

On a positive note, during the quarter, we received an enhanced oil recovery project tax exemption for our Hastings Fields, which resulted in approximately $8 million cumulative reduction in severance taxes during Q3, and will result in lower severance tax payments at that field in the future. This reduction is reflected in our taxes, other than income, line item in our financial statements.

We have also filed for a tax exemption for Oyster Bayou field and are waiting notice of this exemption to be granted. G&A expense was roughly $40 million in Q3, in line with our expectations and about in line with the second quarter level.

For the third quarter, $8 million of net G&A was related to stock-based compensation. In the fourth quarter of 2014, we expect G&A expense to remain around the current level, with approximately $7 million to $10 million of that amount being stock-based compensation.

Our effective income tax rate for Q3 was slightly above our estimated statutory rate of 38%. For 2014, we anticipate our effective tax rate will be between 38% and 39%, with current taxes representing less than 5% of total taxes.

Moving to our capital structure. Total debt at September 30 was approximately $3.6 billion, which was down about $40 million from June 30.

We had $410 million drawn on our bank credit facility at September 30, down $35 million from Q2. Our bank credit facility is set at $1.6 billion, leaving us significant liquidity.

Based on our current assumptions, for cash flows and capital expenditures for 2014 and our level of dividend payments, we anticipate ending the year with debt bank of between $400 million and $500 million, excluding any impact from remaining incremental share repurchases and depending on our level of ultimate capital expenditures. Interest expense, net of amounts capitalized was $45 million in Q3, down roughly $2 million from Q2, due to lower cash interest expense, as a result of lower interest rates and debt outstanding.

Capitalized interest was around $6 million for Q3, relatively unchanged from Q2 and in line with our expectations. We expect capitalized interest to range between $5 million and $6 million for the fourth quarter of 2014.

And now, I'll turn it over to Craig, for his comments.

Okay. Thank you, Mark.

Total company production for the quarter was slightly below 74,000 barrels of oil equivalent per day. Our tertiary oil production averaged just above 41,600 barrels per day, up 2% sequentially, driven by continued growth of Hastings, Heidelberg, Oyster Bayou and Bell Creek fields.

At Hastings, sequential production increased by about 160 barrels per day, as new infill wells came online during the third quarter. Part of this year's capital work program at Hastings included the development and initiation of CO2 injection into 2 new fault blocks, which we refer to us Fault Blocks B and C.

CO2 injection into these new fault blocks was delayed several months to allow time to complete plugging and abandonment work. The P&As took more time than initially anticipated, but were successfully completed in August.

We are modifying our Hastings flood design to what we refer to as a series approach, instead of injecting into multiple stack stands all at once, we're going to focus on flooding the B and C fault blocks, one sand package at a time, similar to the successful approach at Oyster Bayou. We believe this is the more optimal approach.

We are converting several wells now, and we expect a production response from this new fault block in the first quarter of 2015. Moving to Oyster Bayou.

Oyster Bayou continues to show solid reservoir response, increasing by 190 barrels per day sequentially in the third quarter. This increase is due to the reservoir continuing to respond to CO2 injection and initial production response from the A-2 Zone, which occurred in the third quarter.

We are continuing development of Oyster Bayou's A-2 Zone and expect to see additional production growth in the fourth quarter. At Heidelberg, our tertiary production increased about 110 barrels per day from Q2 levels.

We did have are turnaround during the quarter to install a new compressor, which impacted the quarter's production by approximately 200 barrels per day. We expect continued production growth at Heidelberg for the remainder of 2014, as the new Tuscaloosa zone unit comes on production, and CO2 injection is increased in the Utah and Christmas zones, all in East Heidelberg.

At Tinsley, production declined modestly, and included a turnaround to install a new compressor. This field's production is within its estimated peak range.

Two additional dedicated injection wells were recently completed. We do plan on completing Phase 8 field development at Tinsley during the fourth quarter, and expect to see a response in the first half of 2015, which will help mitigate the field's decline.

For our mature area tertiary properties, production increased nearly 90 barrels per day, which was the first sequential quarter increase for these properties since the fourth quarter of 2012. We have implemented various capital projects in several of our mature properties, which help mitigate their production declines.

Let's now move to the Rocky Mountain region. Bell Creek's tertiary production increased over 550 barrels per day during the third quarter, as this field continued to respond well to CO2 injections.

This is despite fluctuations in CO2 delivery volumes from Lost Cabin, and we expect continued growth at Bell Creek in the fourth quarter. Production from our non-tertiary assets decreased 2,240 barrel of oil equivalent per day during the third quarter from just under 34,500 in the second quarter.

This is primarily due to production decreases at Cedar Creek Anticline and Riley Ridge and the Rockies and at Conroe Field and the Gulf Coast region. Production at Conroe Field decreased by approximately 920 barrels of oil equivalent per day on a sequential quarter basis, primarily as a result of downtime of the third-party natural gas processing plant during most of the quarter.

The processing plant returned to service and production, resumed late in the third quarter. Our Cedar Creek Anticline production decreased over 500 barrels of oil equivalent per day during the third quarter, from slightly above 19,000 barrels a day in the second quarter, as we experienced unexpected downtime earlier in the quarter related to this failure and replacement of a large electrical panel, which impacted the water injection of the Cedar Hills South water flood.

Water injection was off-line 8 weeks and resumed in August. Production is now climbing back up and is estimated to return to pre-failure levels by early 2015.

Moving to Riley Ridge. Natural gas production from our Riley Ridge natural gas processing facility was negligible during the third quarter.

Our wells are currently shut in due to the tendency for the tubing to plug with sulfur. This is due to, among other things, a flaw in the initial design, installation of the wells and surface equipment, which have become -- has become more evident as we produce the wells.

Our technical teams have been looking at multiple options to permanently solve this. We have looked at the solutions used by the offset operator, as well as other operators, which produced high hydrogen sulfide concentrations.

We are developing a comprehensive plan to permanently address these well and facility issues in order to ensure sustained throughput from the plant in the future. Based on our current plan, we do not expect natural gas or helium production for the field to resume until late in 2015.

Longer term, Riley Ridge represents the anchor source of CO2 for the Rockies, the near term has minimal cash flow impact. Summing up our company-wide production outlook, we anticipate modest sequential growth in the fourth quarter of 2014, and thus, for our full year 2014 daily production average to be approximately in line with our year-to-date average daily production rate.

Let's move now to lease operating expenses. After excluding the net impact of Delhi field remediation costs and insurance reimbursements, LOE was relatively flat from Q2 on an absolute dollar basis, as an approximate $4 million in incremental costs associated with Riley Ridge, well workovers was largely offset by lower CO2 costs due to lower utilization and lower oil prices.

On a per BOE basis, LOE increased modestly to just over $24 per BOE, primarily due to the sequential 2% decline in total production. It's worth highlighting that our adjusted tertiary LOE per BOE declined 6% on a sequential basis, due to a combination of higher production and lower power and CO2 costs, and it was also down on a year-over-year basis for the first time since the first quarter of 2013.

For Delhi field, the $24 million net insurance reimbursement we received, was partially offset by an additional $14 million of expenses we recorded during the quarter for third-party property and commercial claims, resulting in a $10 million credit to LOE during the third quarter. Also at Delhi, based on preliminary estimates, it would appear that we have achieved payout as of the end of October.

Under the terms of our purchase agreement with our the joint venture partner reversion is scheduled to occur the first day of the month following payout. There continue to be several matters under dispute at Delhi that are being addressed in a lawsuit between us and our joint venture partner.

Turning to a capital program, we have spent 69% of our capital budget through the first 9 months of 2014. We continue to expect our 2014 total combined capital program to come in under the $1.1 billion budget.

Let's move now to our CO2 supply and transportation operations, which continue to fulfill our field needs. In the Gulf Coast region, we produced slightly under 770 million cubic feet per day of CO2 from Jackson Dome during the quarter.

In the Rocky Mountain region, we received about 50 million cubic feet per day of CO2 from our combined sources at LaBarge and Lost Cabin, purchased an addition -- an average of approximately 70 million cubic feet per day of CO2 that was captured from industrial sources in the Gulf Coast region for use in our operator fields in the regions during the third quarter. Our man-made supply is expected to get a boost from the gasification and carbon capture systems at Mississippi Power's Kemper County power plant are started up in the next 12 to 18 months.

Our combination of natural and man-made CO2 sources gives us the ability to manage our CO2 supply, which helps ensure our floods receive the necessary supply. And with that, I'll turn the call back over to Jack.

Okay. Actually, we heard from several of you that we lost audio for a brief period of time at the end of Phil's comment, so Phil's just going to repeat.

Before we open up for Q&A, Phil is going to repeat the last part of this prepared remarks.

So you've heard the details -- so this is kind of going back to 40,000 foot and giving the overview, we're told we lost communication after I was talking about capital, and I was just starting to talk about LOE. So if I could go through those again, then you'll have it.

So I was starting to talk about LOE, and said if you analyzed LOE cost per barrel, they are down about 20% since the fourth quarter of 2013. The $22.86 per barrel this quarter, they were $28.67 per barrel in Q4 of '13.

Unfortunately, if we dig a little deeper, we didn't save quite that much. If you adjust for the non-recurring items related to the Delhi incident, which includes both insurance receipts and incremental charges, and if you adjust for the incremental work-over costs at Riley Ridge this net decrease per barrel is reduced to about 12%, which is still a very positive trend and confirmation that the cost control efforts are paying dividends.

I am disappointed in the overall 2014 production numbers, much of that slippage, as you've heard the detail, can be attributed to continued issues at Riley Ridge that really have minimally impact on cash flow, and lower conventional production at CCA in Conroe. One was related to the unexpected failure of an electrical panel, the other resulted to downtime of a third-party processing plant.

As you've heard, Craig has covered that in a bit more detail. While those items explain much of the shortfall, we really need to improve on our ability to hit our production targets.

I've often said, EOR is extremely difficult to forecast and that is true, as we've found it much harder to predict the precise timing of our production response to CO2, much harder than we had with other conventional in-shell production historically. Interestingly though, this year, while our EOR is running a little bit behind, primarily due to the delays in CO2 injection at Bell Creek discussed earlier this year, the bigger issues have been with conventional production from the aforementioned items.

These production shortfalls are not acceptable and we are working diligently to address them. So with that replay, I will now turn it back to Jack.

Okay. Thank you.

And Zack, you can now open the call up for questions.

Just curious, Craig, maybe this one is for you. The mature property on the tertiary side, you saw that -- that sequential increase of 90 barrels a day, you said that there are several projects going on there.

I guess, how long you, I guess, see or forecast, based on your current project work sort of the flattish mature property profile? And what exactly are you doing at the field level to stimulate that?

Well, specifically, we've got some capital programs released for better costs for a variety of fields. We're just finishing up the development in optimizing -- it's fleshing out some phases in our mature properties, the CO2 patterns as well as optimizing those patterns.

So we spent capital this year on a variety of fields to pursue that. I don't think we are projecting that the mature properties are going to be flat.

That capital investment does a nice job of mitigating the decline, but it's not going to completely offset the decline in the long term.

Yes, we've usually -- if you kind of look at history, we've usually said they've started dropping 10 or maybe a little bit over 10% per year. I think we indicated that we anticipated this year will be a little less than that.

And so it's great to see that it's flat or up slightly quarter-over-quarter. But we don't really think we can maintain that long term, but we do expect it to decline.

Great. And Phil, you went into detail about the lifting cost trajectory and kind of how some of the message was bittersweet there with some frustrations earlier in the year on workovers, but in terms of the actual CO2 expenses, could you quantify have there been any efficiency gains from the amount of CO2 being used at the field level on sort of a year-over-year basis?

Yes. We -- In fact, I guess, we didn't talk about that, quite as much today, but we have definitely lowered our usage of CO2.

So it's a combination -- the CO2 costs were down for a combination of reasons: one is oil price which, of course, affects the cost, particularly on the anthropogenic CO2 on Lost Cabin, makes a big difference. And -- but we've also lowered the usage of CO2 pretty dramatically.

I don't know if you want to comment on that anymore, Craig?

Oh, yes. We talked about it at the last quarter call -- last quarter, we took our CO2 injections down over 100 million a day, which was a nice percentage.

This quarter they're down a little bit more. We -- just as we look at the optimization of CO2 in our fields, we will continue to do that.

And so I don't know, we'll see how dramatic were the changes we've seen in the initial kind of work we've done. I don't know if we're going to take another 100 million out but I think, see improvements in our utilization.

That's just a constant component as we look at how to best manage the reservoirs and optimize their performance.

Great. And if I can just get one quick one in here.

Just -- I think you had said that in the press release you had added hedged volumes since the last quarter, I think, Mark, you -- I just wanted to confirm that you guys are about 75% hedged today for '15 on oil volumes.

Yes. On average, I think we're 58,000 barrels a day for our first 3 quarters and around 38 or so -- so average of 53,000 barrels a day roughly in 2015, combination, not quite 50-50, but of swaps and three-ways.

I think, I mentioned that average kind of downside price if you net all those together was -- I think just under $87 per barrel for 2015. And do recognize that, that includes LLS in which, we generally set those at least $3 per barrel higher when we look at -- doing our contracts.

So...

Okay. And then, I believe that the original plan that you had laid out at your last Analyst Day was based on sort of an $85 realized price, right?

For 2015, it was set at $90. And after that, dropped to $85.

Craig, can we get a little more detail on the 4Q production outlook. Specifically, how much of the non-tertiary production is expected to be back online in the quarter on a daily basis?

Of the non-product -- the non-tertiary production we had a difficulty in the third quarter, should be back up. So it is back up.

Conroe specifically -- the third-party gas plant that was down is back up, so that production has been restored. At Cedar Creek Anticline, just to give you a little more color there, our production is recovering.

As I mentioned in my comments, we don't expect it to fully recover until the first quarter of '15. Just to give you kind of a sense of scale there, we were down for 8 weeks with a very large water injection facility.

That facility puts 33,000 barrels of water in the ground. And so we didn't put 33,000 barrels of water underground for 8 weeks.

That's accumulative of 1.5 million barrels of water. We basically got to put that amount back in the reservoir to get production back up.

And so we're making a good headway. We're seeing the production start to grow in CCA.

But as I mentioned, that -- and we're confident we'll get back to where it was, but that will probably be in the early part of next year.

Okay. And then, so in that case, you're looking for a couple of percentage growth quarter-over-quarter from the tertiary projects.

Our primary growth is going to be in tertiary. As I mentioned, Oyster Bayou is growing and we expect that to continue to grow.

Heidelberg, we expect some growth there. Bell Creek, we should have some growth there as that continues to respond nicely.

Okay. Moving on to the cost side.

Roughly, what -- how much of the say, I guess, it's around $25, $27 of operating costs per barrel for the tertiary projects. For every say $10 decrease in oil price, how much of that move down in general, the CO2 costs power and fuel, et cetera?

We're all looking at each other, scared to answer that one.

We'll talk about that more at the Analyst Meeting if that's okay.

It's a good question, but the contracts are all different. And so, I don't know if we've ever played with sensitivities.

There are certain ones that have -- that aren't linear. And so they're are not -- they don't move in a linear fashion and they're more like a hockey stick.

So you saw a little bit of that benefit, actually, this quarter, which is why it's down a bit. But that doesn't necessarily continue going forward.

So that's a good question. We'll try to address that at the Analyst Meeting.

Okay. And just lastly from me, how are you looking at the share repurchases now?

I know you average in repurchases around the $15 range. And the stock was below that, I imagine, for a decent amount of the third quarter.

You still have about $220 million in the -- outstanding available in the program. How are you looking at it at this point?

Well, it's probably a replay of prior answers. We look at the where it's trading versus NAV, and of course, NAV is dramatically impacted by oil prices.

And so we consider those items and then we consider how we're going to fund it. So the reason we, or at least, part of the reason, anyway, is we've pulled back some is we want to be conscious of our debt levels.

Particularly, in a declining price environment, but it's something we continually watch. And it is a bit subjective that we do have, as you appropriately mention, a little bit over $200 million left on the authorization, but we've been a little cautious perhaps, because of our debt levels and the balance sheet and not knowing for sure where oil prices are going.

Just curious, you kind of mentioned it, but just trying to maybe quantify a bit, but obviously, Riley Ridge, coming down. It just looked like the oil production looks pretty decent from a growth perspective, quarter-over-quarter, sequentially.

The gas obviously, was where the big delta. Was that all pretty much Riley Ridge?

Or is there anything else that was included in that?

Production at -- the Riley Ridge was down, obviously. But also, the CCA was down significantly, and that -- Conroe due to gas...

And those are pretty -- I mean, I guess, I was just more surprised it was such a drop in the gas versus the oil actually hanging in there so to speak?

No. I think, Craig hit them.

We're looking here, it's a cheat sheet. If we get something else, we'll add it.

But I think those are the high points.

Okay. And then maybe just a follow-up on Richard's question.

I mean, are you all able to save much of -- have you looked at anything on the share repurchase side since the quarter closed? I think, the stock actually was above $15, pretty much until the end of the quarter.

And since then, obviously, with what's going on, it's kind of come down, is that commentary still relevant for the last 30, 45 days?

No, we have not -- I guess, we can say that because it becomes public. We haven't purchased anything since the quarter closed.

Phil, I just wanted to, perhaps, get your broader thoughts, I mean, obviously, Denbury has shifted to more of a growth and income kind of strategy. We've had an unexpected down turn in commodity prices.

So I just wanted to get your views on what do you prioritize? Is it growth or income, in a lower oil price environment?

Well, that's a million dollar question. I think, keeping -- part of the priority, I think, keeping dividends, maintaining current dividends is probably one of the highest priorities.

You can debate the rate of growth for the dividends, perhaps, in a declining price environment. And so the next would probably be capital expenditures, which, of course, affects production growth.

So we don't want to shrink dividends ever, if possible. The rate of growth could be flexible, depending on the macro environment.

And just -- because I do believe, just thinking back to history, that you reiterated kind of your tacit views on the '15 dividend in your Q2 release, but there was no specific commentary on that here. Does that suggest that you're still thinking about '15, in terms of the dividend?

Yes, we just didn't want to get into anything related to 2015 when we're only 10 days away from an Analyst Meeting, which we'll include all that, the anticipated 2015 dividend and 2015 capital expenditures and production, et cetera. So we were just trying to stay away from it being so close to our Analyst Meeting.

Okay, okay. That's fair enough.

And just my second question, obviously, there's been a little bit of a timing delta on Riley Ridge. I did dial in a little bit late for the call, but I just wanted to see is, in terms of the cash flow impact of the timing delay, what is does that do to your cash flows in terms of Riley Ridge, if you assume gas prices in the low 4s?

Does that have a material impact at all?

No. No.

It's very immaterial. I mean, it's a -- the primary purpose of Riley Ridge, of course, is to ultimately produce the CO2 for us, and we -- at this point, we still need to have additional separation facilities.

To separate it, we need to have a pipeline there before we can use it. So it is a low-margin process, excluding the usage of CO2.

And so the impact on cash flow -- I don't have a precise number, but it's negligible, it's immaterial.

Okay. And then, maybe, if I could just add one more.

It's just in the broader thoughts on flexibility, on the CapEx side, how much flexibility -- you're spending about $1.1 billion this year. As you think about the next couple of years, how much flexibility -- do you have to downshift that a little bit, while still maintaining, call it, low to mid-single-digit kind of oil growth.

Well, we made that comment early on. See, that's what happens when you're late?

And so you missed all the good part. But we didn't quite cover -- exactly as you said, what we did say is we've -- is kind of reiterate what we've said often, which is, if we could cut capital expenditures by roughly half and keep production relatively flat.

So obviously, something in between gives you, perhaps, some growth. But that's kind of the only place we've gone, we haven't tried to address something in between flat and the current estimates.

Yes, Phil, with the lower oil price environment, are you noticing any changes out on the field, as far as service costs, supply, et cetera, that could help you on your costs for 2015?

This is Craig. Not yet.

We've not. And so our assumptions for 2015 are basically we're not going to see a big increase, we haven't seen those yet, but the market is changing.

We'll see.

Now, are you fairly well locked in for '15 at this point? Or do you have exposure to lower cost?

We don't have many commitments for '15. First of all, we are such a different business.

We don't have bunch of rigs and rig commitments, frac commitments, and all that sort of stuff. We do have some items, we order that have long lead times.

Some of our equipment, particularly, compressors, I think, are still pretty long lead time. So we may have a few of those ordered, but that's relatively minor in the overall scheme of things.

And they're equipment that we would use anyway somewhere, someplace. So I don't think there's a lot of risk in there.

So prices -- we're kind of in a different part of the industry, but if we have some savings, I don't think we have anything locked in that's appreciable.

And then, my follow-up, and this is harder one to ask because you -- we'll have the Analyst Day shortly and get the '15 guidance at that point. So I'm not asking for 2016 guidance, but when you think about dividend policy and setting a dividend, do you want to set it to essentially match the cash flow for that year?

And where I'm going to this is, if in 20 -- let's say the forward curve is indicating lower prices, say, in 2016, you wouldn't want to set the dividend at a level that you have to reduce it the next year, so does that enter into your thought process? Or is it more like, we just want the dividend to essentially, match the cash flow equals CapEx plus dividends.

And so it will move around, up and down, as per how that cash flow moves up and down over time?

We probably do the former part. We'd look forward and look at something that we believe we can sustain, and take that into account when we're setting a -- the current year dividend.

When I compared the presentation for today with last year's investor presentation, the proved and potential remaining in the Delhi field has gone up markedly. Can you explain why that is?

And -- I didn't catch when you said the reversionary was met, was it the beginning of October, or the end of October? When was that?

What we said was based on our preliminary numbers, we -- looks like payout, we have achieved payout at the end of October.

Yes. And with regard to your question about the Delhi potential, I guess, I'm not quite following you there.

Could you...

I don't know that we've covered anything on that today.

No.

On the presentation that I'm looking at on your website, it shows Delhi improved remaining is 29 million barrels equivalent, and the potential is 11 million, and that's compared to 25 million and 8 million from last year's investor presentation.

I think that's just minor tweaks, and we constantly update that based on how the floods going and so forth. But that's not -- one, that's not a very big change.

And anyway, we really haven't addressed any of that really, since, I guess, yearend when we did the reserves.

Okay. Thanks, Zack.

And thank you, again, everyone for joining us on today's call. Before we end the call, let me cover a few housekeeping items.

First, as a reminder, as we've mentioned a few times on today's call, we'll be hosting our annual Analyst Day on Tuesday, November 18, here in Plano. Management's presentation at that Analyst Day, which will include operating and financial guidance for 2015, is scheduled to be begin at 8:00 a.m.

Central. So we hope you all can join us for that.

There will be a live audio webcast of the presentation available on our website. Also, slides for that presentation and the news release that summarizes the key themes of it will be published to our website the evening of Monday, November 17.

Phil and Craig will be giving a recap of that presentation in New York on Wednesday, November 19. Please contact myself or anyone in our Investor Relations group if you'd like to attend either event.

Also, management will be presenting at various conferences in the fourth quarter of this year. A full schedule of those presentations and webcasts will be accessible in the Investor Relations section of our website.

And lastly, please note for your calendars that we plan to report our fourth quarter of 2014 results on Thursday, February 19, 2015 and hold our conference call that day at our usual time of 10:00 am Central. Thanks, again, for joining us, and have a great day.